1. Field of the Invention
Embodiments of the present invention generally relate to running casing into a wellbore. More specifically, embodiments of the present invention relate to managing surge pressure while running casing into the wellbore.
2. Description of the Related Art
To obtain hydrocarbon fluid production from the earth, a wellbore is drilled from the surface of the earth using a drill string. The drill string is a tubular body having a drill bit attached to its lower end for making a hole in the earth. After the drill string has drilled the wellbore to a first depth, the drill string is removed from the wellbore.
Subsequent to removing the drill string from the wellbore, a first section or string of casing is inserted into the drilled-out wellbore. Setting the first casing in the wellbore involves flowing cement into the annulus between the outer diameter of the first casing and the wall of the wellbore, then allowing the cement to cure.
Next, a further portion of wellbore extending to a second depth is drilled below the first portion of wellbore using the drill string. The drill string is removed, and a second casing string or casing section is run into the wellbore through the first casing and into the further portion of the wellbore. The second casing is sometimes termed a “liner” when it is placed below casing already within the wellbore. The second casing has a smaller outer diameter than the inner diameter of the first casing to allow the second casing to run through the first casing. When an upper portion of the second casing reaches a lower portion of the first casing, the second casing is temporarily hung off of the first casing, usually by a hanger. Cement is then flowed into the annulus between the outer diameter of the second casing and the wellbore and allowed to cure to set the second casing within the wellbore. This process is repeated as desired to place casings within the wellbore to form a cased wellbore of the desired depth.
Once the casings of increasing depths are placed within the wellbore, it is often necessary or desirable to run wellbore tools into the casing. Furthermore, after setting the casings within the wellbore at the desired depth for hydrocarbon production, the hydrocarbon fluid may migrate through the inner diameter of the casing within the wellbore to the surface of the wellbore. To allow for the maximum area for fluid flow during hydrocarbon production as well as to permit maximum clearance for wellbore tools through the cased wellbore, it is desirable that the cased wellbore possess the largest inner diameter possible for its depth; therefore, each subsequently-run casing usually has only a slightly smaller outer diameter than the inner diameter of the previously-run casing to allow for maximum effective inner diameter over the depth of the casing within the wellbore.
Because of the small variance between the outer diameter of the subsequently-run casing and the inner diameter of the previously-run casing, little annular clearance between casings may exist during run-in of the casing. The small area of annular clearance between the casings causes a large amount of surge pressure to be imparted on the formation below the previously-run casing when the subsequently-run casing is lowered into the wellbore. Over-pressurizing the formation causes damage to the formation, jeopardizing production of hydrocarbons.
Additionally, when running casing into the wellbore, fluid located within the wellbore tends to flow up through the inner diameter of the casing being run into the wellbore. Because of the pressure exerted on the formation when running in a casing when little annular clearance between casings exists, the fluid may flow from downhole up through the casings to relieve the pressure within the wellbore. The upward flow velocity problem is exacerbated by the presence of the running string used to run each casing into the wellbore. The running string typically has a reduced inner diameter compared to the inner diameter of the casing previously disposed within the wellbore, which causes an increase in pressure within the running string as the fluid flows upward through the running string. Due to the increase in pressure experienced by the fluid flowing upward within the running string, the fluid velocity tends to increase when it flows from the less restricted inner diameter of the disposed casing to the reduced diameter of the running string. An uncontrolled flow of fluid from downhole causes fluid to flow onto the rig floor from downhole, making the rig floor slippery and a safety hazard.
To partially alleviate the surge problem, casings are often run into the wellbore at reduced speeds to decrease pressure on the fluid within the wellbore caused by running in the casing. Reducing the speed of running casings into the wellbore and cleaning up the rig floor increases the amount of time required to obtain a producing wellbore, thus increasing the cost of the wellbore.
A similar problem occurs when running casing into a wellbore formed in a delicate formation, regardless of whether a previous casing exists and regardless of whether the clearance between casings is small. Running casing into a delicate formation could easily result in damage to the formation due to high downhole pressure caused by running the casing into the wellbore.
To prevent the problems that occur due to small clearance in the annulus between casings and due to pressure on delicate formations, diverter tools have been developed to divert fluid into the wellbore annulus while running the casing into the wellbore. The diverter tool is typically a tubular body disposed within the running string which is attached above the running tool, the running tool being connected directly to the casing. One proposed diverter tool includes ports within its tubular body for circulating fluid therethrough while running the casing into the wellbore. The ports are open while the casing is run into the wellbore and can only be closed once; therefore, this diverter tool is a one-shot tool. Generally, the diverter tool utilizes a hydrostatic pressure within a chamber to a move a sleeve to close the ports when a predetermined tool depth is reached. However, the hydrostatic pressure changes due to changes in depth; therefore, this diverter tool may not operate correctly when the wellbore is not a vertical wellbore (e.g., a deviated, lateral, directional, or horizontal wellbore).
Furthermore, when running casing into the wellbore, fluid typically flows upward into the casing as it is run downhole. However, sometimes while running the casing into the wellbore, the casing reaches an obstruction which prevents the casing from running further into the wellbore. The obstruction is often easily removed by circulating fluid down through the casing and out into the wellbore to wash away the obstruction (which may be a portion of the formation). While the proposed diverter tool allows closure of the ports for possible circulation of fluid down through the casing to wash away an obstruction, the one-shot nature of the diverter tool does not allow fluid to flow out through the ports in the diverter tool again as the casing is further lowered into the wellbore subsequent to removal of the obstruction, again creating the problem of a surge of fluid upon further downward movement of the casing into the wellbore due to the absence of a functioning diverter tool. Because the ports of the one-shot diverter tool cannot again be opened while the diverter tool is in the wellbore during the casing running operation, the possibility of formation damage is greatly increased. Consequently, casing running speeds are typically greatly decreased to attempt to minimize formation damage and loss of expensive drilling fluids. If the ports of the diverter tool must be re-opened to further run the casing into the wellbore, the running string must be removed from the wellbore and then again run into the wellbore. Multiple run-ins of the casing and servicing of the diverter tool after its removal from the wellbore add time and thus cost to the formation of the wellbore.
Another proposed diverter tool is run into the wellbore with the casing with the ports in the open position. The diverter tool includes a sleeve therein which moves to close the ports. Extending inward from the sleeve is a restriction in the inner diameter of the diverter tool which is capable of retaining a ball. When it is desired to close the ports, the ball is run into the inner diameter of the diverter tool until it reaches the inner diameter restriction. The ball rests on the inner diameter restriction, and pressurized fluid is flowed into the diverter tool so that the sleeve is forced by the pressure above the ball downward to close the ports. Upon sufficient pressure above the ball, the ball is blown through the restriction so that fluid flow through the diverter tool is again allowed. This diverter tool is disadvantageous because the inner diameter of the diverter tool is restricted. It is often desirable to run tools through the inner diameter of the diverter tool at various points in the operation, and the size of the tools which clear the inner diameter of the diverter tool is limited by a restricted inner diameter portion. Additionally, the area of fluid flow through the diverter tool is decreased by the restriction. This proposed diverter tool is also a one-shot tool which only permits closing the ports once without removing the running string for servicing of the diverter tool causing the same problems encountered in the other proposed diverter tool mentioned above.
Thus, there is a need for a diverter tool having one or more ports which may be opened or closed multiple times without user intervention or action beyond typical casing running operations. There is a further need for a diverter tool which does not restrict the bore of the running string, provides a full-bore opening through the diverter tool, and does not require disposing an external device through the tool to open or close the ports. There is yet a further need for a diverter tool which may be deactivated by an event produced by procedures or tools commonly utilized when running casing into the wellbore.